Origin of crude oils from oilfields in the Zagros Fold Belt,southern Iraq: Relation to organic matter input and paleoenvironmental conditions

Crude oil samples from Cretaceous and Tertiary reservoir sections in the Zagros Fold Belt oil fields, southern Iraq were investigated using non-biomarker and biomarker parameters. The results of this study have been used to assess source of organic matter, and the genetic link between oils and their potential source rocks in the basin. The oils are characterized by high sulphur and trace metal (Ni, V) contents and relatively low API gravity values (17.4–22.7° API). This indicates that these oils are heavy and generated from a marine source rock containing Type II-S kerogen. This is supported by their biomarker distributions of normal alkanes, regular isoprenoids, terpanes and steranes and the bulk carbon isotope compositions of their saturated and aromatic hydrocarbons. The oils are characterized by low Pr/Ph ratios (<1), high values of the C₃₅ homohopane index and C₃₁-22R/C₃₀ hopane ratios, relatively high C₂₇ sterane concentrations, and the predominance of C₂₉-norhopane. These biomarkers suggest that the oils were generated predominantly from a marine carbonate source rock, deposited under reducing conditions and containing plankton/algal and microorganisms source input. The presence of gammacerane also suggests water column stratification during source rock deposition.The biomarker characteristics of the oils are consistent with those of the Middle Jurassic Sargelu carbonate as the effective source rock in the basin. Biomarker maturity data indicate that the oils were generated from early maturity source rocks.     

The petroleum geochemistry of the Termit Basin,Eastern Niger

Sixty crude oils from the Termit Basin (Eastern Niger) were analysed using biomarker distributions and bulk stable carbon isotopic compositions. Comprehensive oil-to-oil correlation indicates that there are two distinct families in the Termit Basin. The majority of the oils are geochemically similar and characterized by low Pr/Ph (pristane to phytane ratios) and high gammacerane/C₃₀ hopane ratios, small amounts of C₂₄ tetracyclic terpanes but abundant C₂₃ tricyclic terpane, and lower δ¹³C values for saturated and aromatic hydrocarbon fractions. All of these geochemical characteristics indicate possible marine sources with saline and reducing depositional environments. In contrast, oils from well DD-1 have different geochemical features. They are characterized by relatively higher Pr/Ph and lower gammacerane/C₃₀ hopane ratios, higher amounts of C₂₄ tetracyclic terpane but a low content of C₂₃ tricyclic terpane, and relatively higher δ¹³C values for saturated and aromatic hydrocarbon fractions. These geochemical signatures indicate possible lacustrine sources deposited under freshwater, suboxic-oxic conditions. This oil family also has a unique biomarker signature in that there are large amounts of C₃₀ 4α-methylsteranes indicating a freshwater lacustrine depositional environment.The maturity of the Termit oils is assessed using a number of maturity indicators based on biomarkers, alkyl naphthalenes, alkyl phenanthrenes and alkyl dibenzothiophenes. All parameters indicate that all of the oils are generated by source rocks within the main phase of the oil generation stage with equivalent vitrinite reflectance of 0.58%–0.87%.     

Oil-oil and oil-source rock correlations in the Alpine Foreland Basin of Austria: Insights from biomarker and stable carbon isotope studies

The Alpine Foreland Basin is a minor oil and moderate gas province in central Europe. In the Austrian part of the Alpine Foreland Basin, oil and minor thermal gas are thought to be predominantly sourced from Lower Oligocene horizons (Schöneck and Eggerding formations). The source rocks are immature where the oil fields are located and enter the oil window at ca. 4 km depth beneath the Alpine nappes indicating long-distance lateral migration. Most important reservoirs are Upper Cretaceous and Eocene basal sandstones.Stable carbon isotope and biomarker ratios of oils from different reservoirs indicate compositional trends in W-E direction which reflect differences in source, depositional environment (facies), and maturity of potential source rocks. Thermal maturity parameters from oils of different fields are only in the western part consistent with northward displacement of immature oils by subsequently generated oils. In the eastern part of the basin different migration pathways must be assumed. The trend in S/(S + R) isomerisation of ααα-C₂₉ steranes versus the αββ (20R)/ααα (20R) C₂₉ steranes ratio from oil samples can be explained by differences in thermal maturation without involving long-distance migration. The results argue for hydrocarbon migration through highly permeable carrier beds or open faults rather than relatively short migration distances from the source. The lateral distance of oil fields to the position of mature source rocks beneath the Alpine nappes in the south suggests minimum migration distances between less than 20 km and more than 50 km.Biomarker compositions of the oils suggest Oligocene shaly to marly successions (i.e. Schoeneck, Dynow, and Eggerding formations) as potential source rocks, taking into account their immature character. Best matches are obtained between the oils and units a/b (marly shale) and c (black shale) of the “normal” Schöneck Formation, as well as with the so-called “Oberhofen Facies”. Results from open system pyrolysis-gas chromatography of potential source rocks indicate slightly higher sulphur content of the resulting pyrolysate from unit b. The enhanced dibenzothiophene/phenanthrene ratios of oils from the western part of the basin would be consistent with a higher contribution of unit b to hydrocarbon expulsion in this area. Differences in the relative contribution of sedimentary units to oil generation are inherited from thickness variations of respective units in the overthrusted sediments. The observed trend towards lighter δ¹³C values of hydrocarbon fractions from oil fields in a W-E direction are consistent with lower δ¹³C values of organic matter in unit c.     

Correlation, alteration, and origin of hydrocarbons in the GCA, Bahar, and Gum Adasi fields, western South Caspian Basin: geochemical and multivariate statistical assessments

Geochemical as well as multivariate statistical analyses (PCA) were carried out on 20 crude oil samples from ‘Middle’ Pliocene Production Series (MPPS) of Guneshli-Chirag-Azeri (GCA), Bahar, and Gum Adasi fields in the western South Caspian Basin (SCB). PCA analysis employed to source-specific biomarkers distinguishes the oils into two types one being divided into two sub-types; Type 1 (GCA oils), Type 2A (Bahar field oils) and Type 2B (Gum Adasi field oils). Indirect oil-to-source rock correlations to available source rock data from previous studies suggest that Type 1 oils, located in the Apsheron-Balkhans uplift area, are derived from basinal shales of the Oligocene-Lower Miocene Middle Maikop Formation. Type 2A and 2B oils, located in the Gum-deniz-Bahar-Shakh-deniz trend area, are more likely derived from shelf-edge shales of the Upper Maikop Formation and the Middle-Upper Miocene Diatom Suite, respectively.Biomarker maturity study reveals that Type 1 oils (mean %Rc=0.78) are more mature than Type 2 oils (mean %Rc=0.71). Source rocks, which generated these oils, were at generation depth interval between 5200 m (112 °C) and 7500 m (153 °C) at the time of expulsion. This indicates that the western SCB oils experienced significant long-range vertical migration along the deep-seated faults to accumulate in the MPPS reservoirs. Post-accumulation biodegradation process was only observed in the Guneshli field where bacterial alteration (level 4) began between 4.2 and 2.6 mybp and stopped with the deposition of the overlying impermeable Upper Pliocene Akchagyl Formation. Subsequent light hydrocarbon (C₁–C₁₆) charge into the Guneshli fields caused precipitation of asphaltenes, which is evidenced by high resin to asphaltene ratios for the present-day Guneshli oils. Evaporative-fractionation examined using the scheme of [Thompson, 1987] showed high correlations of the ‘aromaticity’ B parameter (=toluene/n-C₇) and ‘parafinicity’ F parameter (=n-C₇/MCH with the %Rc (maturity) and C₂₇/C₂₉ sterane ratio (organic matter type). This implies that Thompson's approach should be used with caution in the SCB. Among the several mechanisms, rapid and thick deposition of Pliocene sediments and subsequent high heating rate on the Maikop Formation and Diatom Suite is probably the most plausible way of explaining the origin of light hydrocarbons in the Guneshli and Bahar fields.     

Organic geochemistry of marine source rocks and pyrobitumen-containing reservoir rocks of the Sichuan Basin and neighbouring areas,SW China

Three bitumen fractions were obtained and systematically analysed for the terpane and sterane composition from 30 Paleozoic source rocks and 64 bitumen-containing reservoir rocks within the Upper Sinian, Lower Cambrian, Lower Silurian, Middle Carboniferous, Upper Permian and Lower Triassic strata in the Sichuan Basin and neighbouring areas, China. These bitumen fractions include extractable oils (bitumen I), oil-bearing fluid inclusions and/or closely associated components with the kerogen or pyrobitumen/mineral matrix, released during kerogen or pyrobitumen isolation and demineralization (bitumen II), and bound compounds within the kerogen or pyrobitumen released by confined pyrolysis (bitumen III). In addition, atomic H/C and O/C ratios and carbon isotopic compositions of kerogen and pyrobitumen from some of the samples were measured. Geochemical results and geological information suggest that: (1) in the Central Sichuan Basin, hydrocarbon gases in reservoirs within the fourth section of the Upper Sinian Dengying Formation were derived from both the Lower Cambrian and Upper Sinian source rocks; and (2) in the Eastern Sichuan Basin, hydrocarbon gases in Middle Carboniferous Huanglong Formation reservoirs were mainly derived from Lower Silurian source rocks, while those in Upper Permian and Lower Triassic reservoirs were mainly derived from both Upper Permian and Lower Silurian marine source rocks. For both the source and reservoir rocks, bitumen III fractions generally show relatively lower maturity near the peak oil generation stage, while the other two bitumen fractions show very high maturities based on terpane and sterane distributions. Tricyclic terpanes evolved from the distribution pattern C₂₀ < C₂₁ < C₂₃, through C₂₀ < C₂₁ > C₂₃, finally to C₂₀ > C₂₁ > C₂₃ during severe thermal stress. The concentration of C₃₀ diahopane in bitumen III (the bound components released from confined pyrolysis) is substantially lower than in the other two bitumen fractions for four terrigenous Upper Permian source rocks, demonstrating that this compound originated from free hopanoid precursors, rather than hopanoids bound to the kerogen.     

Characteristics and petroleum origin of the Carboniferous volcanic rock reservoirs in the Shixi Bulge of Junggar Basin,western China

Shixi Bulge of the central Junggar Basin in western China is a unique region that provides insight into the geological and geochemical characteristics of large-scale petroleum reservoirs in volcanic rocks of the western Central Asian Orogenic Belt. Carboniferous volcanic rocks in the Shixi Bulge mainly consist of striped lava and agglomerate, as well as breccia lava and tight tuff. Volcanic rocks differ in porosity and permeability. Striped lava exhibits the highest porosity (average: 14.2%) but the lowest permeability (average: 0.67 × 10⁻¹⁵ m) among the rock types. Primary gas pores are widely developed and mostly filled. Secondary dissolution pores and fractures are two major reservoir storage spaces. Capillary pressure curves suggest the existence of four pore structure types of reservoir rocks. Several factors, namely, lithology, pore structure, and various diagenesis, govern the physical properties of volcanic rocks. The oil is characterized by a high concentration of tricyclic terpane, a terpane distribution of C₂₃ < C₂₁ > C₂₀, and sterane distributions of C₂₇ < C₂₈ < C₂₉ and C₂₇ > C₂₈ < C₂₉. Oil and gas geochemistry revealed that the oil is a mixture derived primarily from P₂w source rock and secondarily from P₁j source rock in the sag west of Pen-1 Well. The gases are likely gas mixtures of humic and sapropelic organic origins, with the sapropelic gas type dominant in the mixture. The gas mixture is most likely cracked from kerogen rather than oils. The Carboniferous volcanic reservoirs in Shixi Bulge share some unique characteristics that may provide useful insights into the various roles of different volcanic reservoir types in old volcanic provinces. The presence of these reservoirs will undoubtedly encourage future petroleum exploration in volcanic rocks up to the deep parts of sedimentary basins.     

Biomarkers of Middle to Late Jurassic marine sediments from a canonical section: New records from the Yanshiping area,northern Tibet

The Yanshiping section, which includes the Quemo Co, Buqu, Xiali, Suowa and Xueshan Formations (Yanshiping Group) exposes organic-rich Middle to Late Jurassic deposits in the Qiangtang Basin of northern Tibet. The biostratigraphic data, from bivalves, brachiopods as well as dinoflagellate cysts, define a Bajocian to Tithonian age. This study focuses on the biomarkers present in these mudstones and limestones to determine the sources, thermal maturity and depositional environment of the organic matter. Most samples show a clear dominance of short-chain (C₁₅–C₂₀) n-alkanes with a maximum at C₁₉ or C₁₉ with a secondary maximum at C₂₃ except for the sample BP01(22)S1 where the predominant range is C₂₂ to C₂₆ with a maximum at C₂₄, significant CPI and odd-to-even predominance. The hopanoids and steroids suggest that the sources of organic matter were dominated by phytoplankton, especially algae, as the primary source. Furthermore, the Pr/Ph, Pr/nC₁₇ and Ph/nC₁₈, with relatively low values plus high abundance of 17α(H)-hopanes, support deposition in dysoxic to reducing, relatively shallow-water depositional settings, and the presence of gammacerane indicates normal marine salinity and/or water-column stratification. All samples are fairly mature with respect to petroleum generation, a conclusion supported by maturity parameters such as C₃₁ 22S/(22S + 22R) hopanes and C₂₉ ααα20S/(20S + 20R) steranes.     

Geochemistry,origin, and accumulation of petroleum in the Eocene Wenchang Formation reservoirs in Pearl River Mouth Basin,South China Sea: A case study of HZ25-7 oil field

The Pearl River Mouth Basin in the South China Sea has accumulated >2 km of Eocene sediments in its deep basin, and has become the exploration focus due to the recent discoveries of the HZ25-7 oil field in the Eocene Wenchang (E₂w) Formation. In this study, the geochemical characteristics of potential source rocks and petroleum in the HZ25-7 oil field are investigated and the possible origins and accumulation models developed. The analytical results reveal two sets of potential source rocks, E₂w and Enping (E₂e) formations developed in the study area. The semi-deep-to-deep lacustrine E₂w source rocks are characterized by relatively low C₂₉ steranes, low C₁₉/C₂₃ tricyclic terpane (<0.6), low C₂₄ tetracyclic terpane/C₃₀ hopane (<0.1), low trans-trans-trans-bicadinane (T)/C₃₀ hopane (most <2.0), and high C₃₀ 4-methyl sterane/ΣC₂₉ sterane (>0.2) ratios. In contrast, the shallow lacustrine and deltaic swamp-plain E₂e source rocks are characterized by relatively high C₂₉ steranes, high C₁₉/C₂₃ tricyclic terpane (>0.6), high C₂₄ tetracyclic terpane/C₃₀ hopane (>0.1), variable yet overall high T/C₃₀ hopane, and low C₃₀ 4-methyl sterane/ΣC₂₉ sterane (<0.2) ratios. The relatively low C₁₉/C₂₃ tricyclic terpane ratios (mean value: 0.39), low C₂₄ tetracyclic terpane/C₃₀ hopane ratios (mean value: 0.07), high C₃₀ 4-methyl sterane/ΣC₂₉ sterane ratios (mean value: 1.14), and relatively high C₂₇ regular sterane content of petroleum in the HZ25-7 oil field indicate that the petroleum most likely originated from the E₂w Formation mudstone in the Huizhou Depression. One stage of continuous charging is identified in the HZ25-7 oil field; oil injection is from 16 Ma to present and peak filling occurs after 12 Ma. Thin sandstone beds with relatively good connectivity and physical properties (porosity and permeability) in the E₂w Formation are favorable conduits for the lateral migration of petroleum. This petroleum accumulation pattern implies that the E₂w Formation on the western and southern margins of the Huizhou Depression are favorable for petroleum accumulation because they are located in a migration pathway. Thus exploration should focus in these areas in the future.     

Fluid circulation and formation of minerals and bitumens in the sedimentary rocks of the Outer Carpathians – Based on studies on the quartz–calcite–organic matter association

Different methods have been used to examine minerals and/or solid bitumens in three adjacent Carpathian regions of Poland, Ukraine and Slovakia. The minerals fill smaller and larger veins and cavities, where they occur either together or separately. They usually co-occur with the solid bitumens. All δ¹³C_PDB values measured for calcite lie in a relatively wide interval between −6.25‰ and +1.54‰, while most values fall into the narrower interval from below 0 to about −3‰. The general range of calcite δ¹⁸O results for the whole studied region is between +17.13‰ and +25.23‰ VSMOW or from about −11 to −5‰ VPDB, while the majority of these values are between +20.0 and 23.5‰ VSMOW (−10.53 and −8.00‰ PDB, respectively). δ¹⁸O_VSMOW results for quartz vary between +23.2 and 27.6. The carbonate percentage determined in some samples falls between from <2% CaCO₃ to >90% CaCO₃, while the TOC values changes from 0.09% to over 70%.The aliphatic fraction predominates in all studied samples, mainly in bitumens and oils. The composition of the aliphatic fraction is relatively homogeneous and points to a strong aliphatic, oil-like paraffin character of the bitumens. Such a composition is characteristic of the Carpathian oils and different from the rocks studied that contain the higher percentage of a polar fraction. The content of the aliphatic fraction in bitumens is only slightly higher than that in two oils used for comparison. The distribution of n-alkanes is variable in rocks, solid bitumens as well as inclusions in quartz and calcite. Two groups of bitumens may be distinguished. Those with a predominance of long-chain n-alkanes in the C₂₅–C₂₇ interval (in some cases from C₂₃–C₂₅ and without or with a very low concentration of short-chain n-alkanes in the interval of C₁₄–C₂₁) show also a high content of isoprenoids i.e. of pristane (Pr) and phytane (Ph). In all but one bitumen samples, Pr predominates over Ph. The second group comprises oils and rock samples with a characteristic predominance of short-chain n-alkanes in the interval from C₁₃–C₁₉ and a low percentage of the long-chain n-alkanes from the n-C₂₇–n-C₃₃ interval. Pristane and phytane exhibit a concentration comparable to that of C₁₇ and C₁₈ n-alkanes with a Pr predominance over Ph. Due to high maturity, only small amounts of the most stable compounds from the hopane group have been observed in the samples, also oleanane in one case. Among the aromatic hydrocarbons, phenanthrene and its methyl- and dimethyl-derivatives are dominant in bitumens, source rocks and inclusions in calcite and quartz. Occurrence of cyclohexylbenzene and its alkyl-derivatives as well as cyclohexylfluorenes in solid bitumens suggest that they formed from oil accumulations under the influence of relatively high temperatures in oxidizing conditions.Homogenization temperatures for aqueous/brine inclusions in quartz within the Dukla and Silesian units (Polish and Ukrainian segments) are between 125 and 183.9 °C, while salinities are low in the interval of 0.2–5.5 wt% NaCl eq. The inclusions in calcite homogenize at higher temperatures of almost 200 °C and the brine displays higher salinity than the fluid in the quartz. Two quartz generations may be distinguished by inclusion and isotope characteristics and the macroscopic diversity. Oil inclusions homogenize at 95 °C. One phase inclusions in quartz contain methane, CO₂ and nitrogen in variable proportions.     

Organic geochemistry of the Silurian Tanezzuft Formation and crude oils,NC115 Concession,Murzuq Basin,southwest Libya

Thirty-six Silurian core and cuttings samples and 10 crude oil samples from Ordovician reservoirs in the NC115 Concession, Murzuq Basin, southwest Libya were studied by organic geochemical methods to determine source rock organic facies, conditions of deposition, thermal maturity and genetic relationships. The Lower Silurian Hot Shale at the base of the Tanezzuft Formation is a high-quality oil/gas-prone source rock that is currently within the early oil maturity window. The overall average TOC content of the Hot Shale is 7.2 wt% with a maximum recorded value of 20.9 wt%. By contrast, the overlying deposits of the Tanezzuft Formation have an average TOC of 0.6 wt% and a maximum value of 1.1 wt%. The organic matter in the Hot Shale consists predominantly of mixed algal and terrigenous Type-II/III kerogen, whereas the rest of the formation is dominated by terrigenous Type-III organic matter with some Type II/III kerogen. Oils from the A-, B- and H-oil fields in the NC115 Concession were almost certainly derived from marine shale source rocks that contained mixed algal and terrigenous organic input reflecting deposition under suboxic to anoxic conditions. The oils are light and sweet, and despite being similar, were almost certainly derived from different facies and maturation levels within mature source rocks. The B-oils were generated from slightly less mature source rocks than the others. Based on hierarchical cluster analysis (HCA), principal component analysis (PCA), selected source-related biomarkers and stable carbon isotope ratios, the NC115 oils can be divided into two genetic families: Family-I oils from Ordovician Mamuniyat reservoirs were probably derived from older Palaeozoic source rocks, whereas Family-II oils from Ordovician Mamuniyat–Hawaz reservoirs were probably charged from a younger Palaeozoic source of relatively high maturity. A third family appears to be a mixture of the two, but is most similar to Family-II oils. These oil families were derived from one proven mature source rock, the Early Silurian, Rhuddanian Hot Shale. There is a good correlation between the Family-II and -III oils and the Hot Shale based on carbon isotope compositions. Saturated and aromatic maturity parameters indicate that these oils were generated from a source rock of considerably higher maturity than the examined rock samples. The results imply that the oils originated from more mature source rocks outside the NC115 Concession and migrated to their current positions after generation.     

Characteristics and origin of carbon isotopes of n-alkanes in crude oils from the western Pearl River Mouth Basin,South China sea

The quantitative characterization of carbon isotopes of n-alkanes is commonly carried out in organic geochemical studies. Possible controls on carbon isotopes include source organic matter, maturity, fractionation during oil expulsion and migration, and the mixing of different oils. In this study of the origin of crude oils in the western Pearl River Mouth Basin, the influences of all of these factors have been considered in reaching a conclusion. Carbon isotopes of n-alkanes in the crude oils, and the extracts of the two effective source rocks (the Wenchang and Enping formations) in the basin, exhibit clear differences. The Wenchang source rocks have heavy δ¹³C values that remain almost constant or become slightly heavier with increasing carbon number. The Enping source rocks have light δ¹³C values that become lighter with increasing carbon number. Two groups of oils in this area were identified based on the carbon isotopes of the n-alkanes; groupIoils are similar to extracts of the Wenchang source rocks. However, the groupIIoils are different from both the Wenchang and Enping source rocks and the carbon isotopic profiles of their n-alkanes exhibit a “V” feature with increasing carbon number. The results of artificial thermal maturation experiments indicate that, from the early stage to the peak stage of oil generation (with EasyRo between 0.64% and 1.02%), the δ¹³C values of n-alkanes in the pyrolysis oils become heavier by about 3‰ with increasing thermal maturity, but the shape of the carbon isotopic profiles are not significantly changed. Calculated δ¹³C values of n-alkanes in “mixed” artificial pyrolysis oils indicate that the mixture of oils generated from the same source rocks with different maturities could not change the carbon isotopic profile of the n-alkanes, however, a mixing of the Wenchang and Enping oils could give the “V” feature in the profiles, similar to the groupIIoils in this area. The groupIIoils appear to be mixed Wenchang and Enping oils, the latter being the dominant component in the mixture. We conclude that the source organic matter and the degree of mixing are the main factors controlling the carbon isotopic characteristics of n-alkanes in crude oils in the western Pearl River Mouth Basin.     

Transport and fate of Danube Delta terrestrial organic matter in the Northwest Black Sea mixing zone

Within the framework of the European project EROS 21, a biogeochemical study of particles transported from the Danube Delta to the Northwestern Black Sea whose carbon cycle is dominated by riverine inputs was carried out in spring off the Sulina branch of the Danube Delta. The distribution of particulate organic carbon (POC), chlorophyll a (Chl a), C/N, and δ¹³C evidenced an omnipresent contribution of terrestrial organic matter throughout the study area together with a dilution of these inputs by freshwater and marine organisms. Four lipid series, n-alkanoic acids, n-alkanes, n-alkanols, and sterols were analyzed by gas chromatography and gas chromatography/mass spectrometry. Several signature compounds were selected to delineate dispersion of terrestrial organic carbon: (1) long-chain n-alkanoic acids in the range C₂₄–C₃₄, long-chain n-alkanes in the range C₂₅–C₃₅, long-chain n-alkanols in the range C₂₂–C₃₀, 24-ethylcholesta-5,22-dien-3β-ol (29Δ^5,22) and 24-ethylcholesterol (29Δ⁵) for vascular plant-derived material and (2) coprostanol (27Δ^0,5β) for faecal contamination associated with sewage effluents. A marked decrease was observed between the concentrations of different vascular plant markers characterizing the two end members: riverine at salinity 0.3 and marine at salinity 15.5. The decrease observed for marine/riverine end members (expressed as a function of organic carbon) varied in a large range, from 4% for n-alkanes to 18.6%, 20.4% and 24% for n-fatty acids, n-alkanols and sterols, respectively. These values reflect a combination of various processes: size-selective particle sedimentation, resuspension of different particle pools of different sizes and ages, and/or selective biological utilization. The multi-marker approach also suggested the liberation in the mixing zone of terrestrial moieties, tightly trapped in macromolecular structures of the riverine material. The greatest decrease for marine/riverine end members was observed for coprostanol (0.9%), underlining the efficiency of the mixing zone as a sink for sewage-derived carbon.     

Bulk organic δC and C/N as indicators for sediment sources in the Pearl River delta and estuary,southern China

Preservation of organic matter in estuarine and coastal areas is an important process in the global carbon cycle. This paper presents bulk δ¹³C and C/N of organic matter from source to sink in the Pearl River catchment, delta and estuary, and discusses the applicability of δ¹³C and C/N as indicators for sources of organic matter in deltaic and estuarine sediments. In addition to the 91 surface sediment samples, other materials collected in this study cover the main sources of organic material to estuarine sediment. These are: terrestrial organic matter (TOM), including plants and soil samples from the catchment; estuarine and marine suspended particulate organic carbon (POC) from both summer and winter. Results show that the average δ¹³C of estuarine surface sediment increases from −25.0 ± 1.3‰ in the freshwater environment to −21.0 ± 0.2‰ in the marine environment, with C/N decreasing from 15.2 ± 3.3 to 6.8 ± 0.2. In the source areas, C₃ plants have lower δ¹³C than C₄ plants (−29.0 ± 1.8‰ and −13.1 ± 0.5‰ respectively). δ¹³C increases from −28.3 ± 0.8‰ in the forest soil to around −24.1‰ in both riverbank soil and mangrove soil due to increasing proportion of C₄ grasses. The δ¹³C_POC increases from −27.6 ± 0.8‰ in the freshwater areas to −22.4 ± 0.5‰ in the marine-brackish-water areas in winter, and ranges between −24.0‰ in freshwater areas and −25.4‰ in brackish-water areas in summer. Comparison of the δ¹³C and C/N between the sources and sink indicates a weakening TOM and freshwater POC input in the surface sedimentary organic matter seawards, and a strengthening contribution from the marine organic matter. Thus we suggest that bulk organic δ¹³C and C/N analysis can be used to indicate sources of sedimentary organic matter in estuarine environments. Organic carbon in surface sediments derived from anthropogenic sources such as human waste and organic pollutants from industrial and agricultural activities accounts for less than 10% of the total organic carbon (TOC). Although results also indicate elevated δ¹³C of sedimentary organic matter due to some agricultural products such as sugarcane, C₃ plants are still the dominant vegetation type in this area, and the bulk organic δ¹³C and C/N is still an effective indicator for sources of organic matter in estuarine sediments.     

Mechanisms of petroleum accumulation in the Bozhong sub-basin, Bohai Bay Basin, China. Part 1: Origin and occurrence of crude oils

The origin of the fourteen major oil fields in the Bozhong sub-basin, Bohai Bay basin was studied based on the results of Rock-Eval pyrolysis on more than 700 samples and biomarker analysis on 61 source rock samples and 87 oil samples. The three possible source rock intervals have different biomarker assemblages and were deposited in different environments. The third member of the Oligocene Dongying Formation (E₃d₃, 32.8–30.3 Ma in age) is characterized mainly by high C₁₉/C₂₃ tricyclic terpane (>0.75), high C₂₄ tetracyclic terpane/C₂₆ tricyclic terpane (>2.5), low gammacerane/αβ C₃₀ hopane (<0.15) and low 4-methyl steranes/ΣC₂₉ steranes (<0.15) ratios, and was deposited in sub-oxic to anoxic environments with significant terrigenous organic matter input. The first (E₂s₁, 35.8–32.8 Ma) and third (E₂s₃, 43.0–38.0 Ma) members of the Eocene Shahejie Formation have low C₁₉/C₂₃ tricyclic terpane and low C₂₄ tetracyclic terpane/C₂₆ tricyclic terpane ratios and were deposited in anoxic environments with minor terrestrial organic matter input, but have different abundances of 4-methyl steranes and gammacerane. The hydrocarbon-generating potential and biomarker associations of these three source rock intervals were controlled by tectonic evolution of the sub-basin and climate changes. Three oil families derived from E₂s₃, E₂s₁ and E₃d, respectively, and three types of mixed oils have been identified. All large oil fields in the Bozhong sub-basin display considerable heterogeneities in biomarker compositions and originated from more than one source rock interval, which suggests that mixing of oils derived from multiple source rock intervals or multiple generative kitchens, and/or focusing of oils originated from a large area of a generative kitchen, is essential for the formation of large oil fields in the Bozhong sub-basin. E₂s₃- and E₂s₁-derived oils experienced relatively long-distance lateral migration and accumulated in traps away from the generative kitchen. E₃d₃-derived oils had migrated short distances and accumulated in traps closer to the generative kitchen. Such a petroleum distribution pattern has important implications for future exploration. There is considerable exploration potential for Dongying-derived oils in the Bozhong sub-basin, and traps close to or within the generative kitchens have better chance to contain oils generated from the Dongying Formation.     

Petroleum accumulation in the deeply buried reservoirs in the northern Dongying Depression,Bohai Bay Basin,China: New insights from fluid inclusions,natural gas geochemistry,and 1-D basin modeling

The deeply buried reservoirs (DBRs) from the Lijin, Shengtuo and Minfeng areas in the northern Dongying Depression of the Bohai Bay Basin, China exhibit various petroleum types (black oil-gas condensates) and pressure systems (normal pressure-overpressure) with high reservoir temperatures (154–185 °C). The pressure-volume-temperature-composition (PVTX) evolution of petroleum and the processes of petroleum accumulation were reconstructed using integrated data from fluid inclusions, stable carbon isotope data of natural gas and one-dimensional basin modeling to trace the petroleum accumulation histories.The results suggest that (1) the gas condensates in the Lijin area originated from the thermal cracking of highly mature kerogen in deeper formations. Two episodes of gas condensate charging, which were evidenced by the trapping of non-fluorescent gas condensate inclusions, occurred between 29-25.5 Ma and 8.6–5.0 Ma with strong overpressure (pressure coefficient, P_c = 1.68–1.70), resulting in the greatest contribution to the present-day gas condensate accumulation; (2) the early yellow fluorescent oil charge was responsible for the present-day black oil accumulation in well T764, while the late blue-white oil charge together with the latest kerogen cracked gas injection resulted in the present-day volatile oil accumulation in well T765; and (3) the various fluorescent colors (yellow, blue-white and blue) and the degree of bubble filling (F_v) (2.3–72.5%) of the oil inclusions in the Minfeng area show a wide range of thermal maturity (API gravity ranges from 30 to 50°), representing the charging of black oil to gas condensates. The presence of abundant blue-white fluorescent oil inclusions with high Grain-obtaining Oil Inclusion (GOI) values (35.8%, usually >5% in oil reservoirs) indicate that a paleo-oil accumulation with an approximate API gravity of 39–40° could have occurred before 25 Ma, and gas from oil cracking in deeper formations was injected into the paleo-oil reservoir from 2.8 Ma to 0 Ma, resulting in the present-day gas condensate oil accumulation. This oil and gas accumulation model results in three oil and gas distribution zones: 1) normal oil reservoirs at relatively shallow depth; 2) gas condensate reservoirs that originated from the mixture of oil cracking gas with a paleo-oil reservoir at intermediate depth; and 3) oil-cracked gas reservoirs at deeper depth.The retardation of organic matter maturation and oil cracking by high overpressure could have played an important role in the distribution of different origins of gas condensate accumulations in the Lijin and Minfeng areas. The application of oil and gas accumulation models in this study is not limited to the Dongying Depression and can be applied to other overpressured rift basins.     

Organic matter source and thermal maturity within the Late Cretaceous Niobrara Formation,U.S. Western Interior

The Late Cretaceous sedimentary record of the North American Western Interior Seaway is characterized by cyclic deposition of organic carbon-rich sediments. One notable interval during the late Coniacian-Santonian is recorded by the Niobrara Formation. The organic carbon-rich interval within the Niobrara Formation has been identified as Oceanic Anoxic Event (OAE) 3. Understanding the reason for this distribution of organic carbon within the Niobrara Formation requires a refined understanding of the source and maturity of the organic matter. In this study, we present lipid biomarker records from the USGS Portland #1 core (Cañon City, CO) to constrain the thermal maturity of the organic matter and the differing contributions of organic matter sources. Sterane and hopane thermal maturity indices indicate that the samples are somewhat immature with respect to oil formation and that there is strong agreement between different proxies for thermal maturity. Based on the distribution of n-alkanes, steranes, and hopanes, there is a significant increase in the contribution of algal organic matter during and after OAE 3, coeval with increased organic carbon accumulation. Although a consistent terrestrial contribution is observed, it is only a minor source of organic matter at the Portland core location and does not drive increased organic matter accumulation during OAE 3. Of particular note is the consistent influence of even-over-odd predominantly mid-chain length (C₂₁ to C₂₅) organic matter. This observation within the brackish to marine, not methanogenic WIS represents an expansion of the depositional settings in which even-over-odd predominance has been observed in mid-chain length n-alkanes. Pristane (Pr) and phytane (Ph) abundances are inconsistent with a redox control on Pr/Ph ratios and suggest an increase in the delivery and/or preservation of phototrophic organic matter as the source for pristane and phytane in the Portland core.     

Sedimentary and residual gas geochemical characteristics of the Lower Cambrian organic-rich shales in Southeastern Chongqing,China

To study the sedimentary environment of the Lower Cambrian organic-rich shales and isotopic geochemical characteristics of the residual shale gas, 20 black shale samples from the Niutitang Formation were collected from the Youyang section, located in southeastern Chongqing, China. A combination of geochemical, mineralogical, and trace element studies has been performed on the shale samples from the Lower Cambrian Niutitang Formation, and the results were used to determine the paleoceanic sedimentary environment of this organic-rich shale. The relationships between total organic carbon (TOC) and total sulfur (TS) content, carbon isotope value (δ¹³C_org), trace element enrichment, and mineral composition suggest that the high-TOC Niutitang shale was deposited in an anoxic environment and that the organic matter was well preserved after burial. Stable carbon isotopes and biomarkers both indicate that the organic matter in the Niutitang black shales was mainly derived from both lower aquatic organisms and algaes and belong to type I kerogen. The oil-prone Niutitang black shales have limited residual hydrocarbons, with low values of S₂, I_H, and bitumen A. The carbon isotopic distribution of the residual gas indicate that the shale gas stored in the Niutitang black shale was mostly generated from the cracking of residual bitumen and wet gas during a stage of significantly high maturity. One of the more significant observations in this work involves the carbon isotope compositions of the residual gas (C₁, C₂, and C₃) released by rock crushing. A conventional δ¹³C₁–δ¹³C₂ trend was observed, and most δ¹³C₂ values of the residual gases are heavier than those of the organic matter (OM) in the corresponding samples, indicating the splitting of ethane bonds and the release of smaller molecules, leading to ¹³C enrichment in the residual ethane.     

Geochemical characteristics of Tertiary coal-bearing source rocks in Xihu depression,East China Sea basin

This study aims at investigating hydrocarbon generation potential and biological organic source for the Tertiary coal-bearing source rocks of Pinghu Formation (middle-upper Eocene) in Xihu depression, East China Sea shelf basin. Another goal is to differentiate coal and mudstone with respect to their geochemical properties. The coal-bearing sequence has a variable organofacies and is mainly gas-prone. The coals and carbonaceous mudstones, in comparison with mudstones, have a higher liquid hydrocarbon generation potential, as reflected by evidently higher HI values (averaging 286 mg HC/g C) and H/C atomic ratios (round 0.9). The molecular composition in the coal-bearing sequence is commonly characterized by unusually abundant diterpenoid alkanes, dominant C₂₉ sterane over C₂₇ and C₂₈ homologues and high amount of terrigenous-related aromatic biomarkers such as retene, cadalene and 1, 7-dimethylphenanthrene, indicating a predominantly terrigenous organic source. The source rocks show high Pr/Ph ratios ranging mostly from 3.5 to 8.5 and low MDBTs/MDBFs ratios (<1.0), indicating deposition in an oxic swamp-lacustrine environment. The coals and carbonaceous mudstones could be differentiated from the grey mudstones by facies-dependent biomarker parameters such as relative sterane concentration and gammacerane index and carbon isotope composition. Isotope and biomarker analysis indicate the genetic correlation between the Pinghu source rocks and the oils found in Xihu depression. Moreover, most oils seem to be derived from the coal as well as carbonaceous mudstone.     

Geochemistry and charge history of oils from the Yuqi area of Tarim Basin,NW China

The geochemistry, origin and charge history of oils from the Yuqi area of Tarim Basin have been investigated, through GC, GC-MS and fluid inclusion microthermometry analysis. The Yuqi oils accumulated mainly in three intervals: (1) in the Lower-Middle Ordovician Yingshan Formation (O_1-2y) carbonate reservoirs; (2) in the overlying Upper Triassic Halahatang Formation (T₃h); and (3) in the Lower Cretaceous Yageliemu Formation (K₁y) sandstones. Oils from different reservoirs have distinct physical properties, varying from extra-heavy (O_1-2y), heavy (T₃h), to light oils (T₃h and K₁y). However, their geochemical compositions show a high degree of similarity, which indicates that they derive from the same source rock. Abundant tricyclic terpanes, gammacerane, dibenzothiophene and C₂₁C₂₂steranes, together with a low level of diasteranes, indicate an anoxic marine source rock for oils in the Yuqi area. Oil-oil correlation shows that Yuqi oils derive from the same source bed as Tahe oils. The co-occurrence of intact n-alkanes and 25-norhopanes in all the samples supports the proposition that there is a mixture of an early filled severely biodegraded oil and a late filled fresh oil.In this study, charge history is examined on the basis of integration of fluid inclusion homogenization temperature data with 1D burial-thermal history models. Two episodes of oil charging are identified in the O_1-2y reservoir (well YQX1-1) at around 436-420 Ma (Middle-Late Silurian) and 10-3 Ma (Miocene to Pliocene), respectively. For the samples from the T₃h and K₁y intervals, only one episode of oil charge is indicated by the homogenization temperatures of coexisting aqueous inclusions with an inferred timing around 10-3 Ma. The T₃h heavy oil reservoir is assumed to be a secondary hydrocarbon pool, which accumulated by re-migration and re-distribution of hydrocarbons from O_1-2y hydrocarbon pools. The few early biodegraded oils in the K₁y light oils were probably picked up along the migration pathway during the late fresh oil charging.     

Stable Isotopic Composition of Particulate Organic Carbon in the Caspian Sea

The data on the isotopic composition of particulate organic carbon (δ¹³C_POC) in the Caspian Sea water in summer–autumn 2008, 2010, 2012, and 2013 are discussed in the paper. These data allowed as to reveal the predominant genesis of organic carbon in suspended particulate matter of the active seawater layer (from 0 to 40 m). The δ¹³C_POC =–27‰ (PDB) and δ¹³C_POC =–20.5‰ (PDB) values were taken as the reference data for terrigenous and planktonogenic organic matter, respectively. Seasonal (early summer, late summer, and autumn) variations in the composition of suspended particulate matter in the active sea layer were revealed. A shift of δ¹³C_POC towards greater values was seen in autumn (with a slight outburst in the development (bloom) of phytoplankton) in comparison with summer (with large accumulations and an extraordinary phytoplankton bloom confined to the thermocline area). The seasonal dynamics of autochthonous and allochthonous components in the suspended particulate matter of the Middle and Southern Caspian Sea was studied with the use of data on the concentration of particulate matter and chlorophyll a, the phytoplankton biomass and the POC content.